Tubulars used to drill and complete bore holes in earth materials are typically joined by threaded connections. Numerous threaded connection geometries are employed to provide sealing and load-carrying capacities to meet drilling, installation and operating requirements. Of these geometries, tapered pipe threads are among the simplest and most widely used.
Within the context of petroleum drilling and well completion, wells are typically constructed by drilling the well bore using one tubular string, largely made up of drill pipe, then removing the drill pipe string and completing by installing a second tubular string, referred to as casing, which is subsequently permanently cemented in place. The tubular strings are formed by connecting lengths of pipe, referred to as joints, with threaded connections. With this traditional method of well construction, both the drill pipe and casing joint designs are separately optimized for the different performance requirements of the drilling and completion operations respectively. More specifically, the drill pipe connections must accommodate torque required to drill, which is not required during completion.
Recent advances in drilling technology have enabled wells to be drilled and completed with a single casing string, eliminating the need to ‘trip’ the drill pipe in and out of the hole to service the bit and make room for the casing upon completion of drilling. This change is motivated by potential cost savings arising from reductions in drilling time and the expense of providing and maintaining the drill string, plus various technical advantages, such as reduced risk of well caving before installation of the casing.
However, using casing to both drill and complete the well changes the performance requirements of the casing string, and more particularly the torque capacity of the casing connections, from those established through use within the traditional methods of well construction.
The most widely used of casing connections are the industry standard threaded and coupled buttress (BTC) and 8-round (LTC or STC) connections having tapered pipe thread geometries specified by the American Petroleum Institute (API). These connections have limited torque capacity and are thus not well suited to the casing drilling application, but are readily available and relatively inexpensive. To more fully realize the potential benefit of this emerging casing drilling system (CDS) technology, it is therefore desirable to find means to press these industry standard connections into service by identifying means to inexpensively increase their torque capacity.
Similar motivations to improve the sealing capacity of connections using API thread forms have led to the invention of apparatus and methods such as described in U.S. Pat. Nos. 4,706,997, 4,878,285, 5,283,748, 5,689,871, and 4,679,831. These patents generally describe inventions where a modified coupling, provided with an internal floating sleeve or seal ring, is employed to join pipes having standard API thread forms on their pin ends. The seal ring is positioned in the so-called J-section space between the pin ends of a made-up threaded and coupled connection. The seal ring internal diameter is approximately matched to the internal pipe diameter and is coaxially placed inside the coupling at its mid-plane so as to engage both pin ends when the connection is made up. According to the teachings of these inventions, this engagement or shouldering is primarily intended to enhance the seal performance of the connection beyond that provided by the standard API configuration. Several additional benefits are also obtained, such as improved flow performance and a smooth-running bore. The use of resilient materials in conjunction with the rigid seal ring or as separate seals is also taught as a means to further promote sealing.
While these descriptions of the prior art do not explicitly address the utility of such a “convertible metal ring” or seal ring as a means to improve the torque capacity otherwise available from API connections, the increased torque capacity is a well-known benefit. In fact, manufacturers of such connections quantify this parameter in published performance data such as provided by Hunting Oilfield Services for a product described as “the KC Convertible coupling system”.
These prior art implementations of rigid seal rings recognise that the wide tolerance variation allowed for the pin and box geometries of threaded and coupled connections meeting API specifications permits a correspondingly wide range of axial position after make-up, if a satisfactory level of interference or “dimensional control” is to be achieved (see U.S. Pat. No. 5,283,748). Consequently, to obtain satisfactory “dimensional control”, this prior art teaches that additional measures must be taken to reduce the tolerance range of pins and/or boxes provided for use with seal rings and to control the make-up position. Such steps include specifically manufacturing “modified boxes” to tighter tolerances than required by API specifications, and pre-screening of product manufactured to API tolerances to similarly obtain pins and boxes having more precisely controlled geometry. To ensure controlled placement and retention of the seal ring, it is taught that additional machining of the coupling's central thread region is required to form a seat for the seal ring. To obtain dimensional control of the so-called mill end make-up position, additional fixtures or measurements are required.
However, these prior art couplings require modification of the standard API components or increased quality control and, therefore, substantially reduce the benefits of low cost and simplicity originally sought from using existing industry standard couplings and pins. In addition, prior art couplings are in large part motivated by the desire to upgrade the pressure containment capacity of API connections and, as such, are not optimized to obtain the upgraded torque capacity desired for casing drilling applications.
U.S. Pat. No. 6,899,356 discloses a floating shoulder ring that may be used to substantially increase the ability of tubular connections to transmit torque. When placed internally between the pipe ends of a threaded and coupled pipe connection, the shoulder ring acts as a floating internal upset coupling shoulder capable of reacting compressive axial load between the pin ends and thus enhancing the connection torque capacity. The shoulder ring of U.S. Pat. No. 6,899,356 is particularly useful as a means to upgrade the torque capacity of tapered couplings such as, for example, unmodified API buttress and round threaded and coupled connections, manufactured to industry standard tolerances, to meet the requirements of casing drilling applications. The shoulder ring is placed substantially coaxially in the coupling of the connection, between the pin ends of the joined tubulars.
To be most generally useful for these applications, the floating shoulder ring should be amenable to rapid field installation on joints with couplings already bucked on (for example, in accordance with existing procedures as generally specified by API), without damaging the connection threads. It should be anchored or fixed securely enough to prevent being dislodged or knocked out from loads arising due to handling and installation operations such as make-up, break-out, or equipment movement in and out of the open-ended casing in the rig floor. In addition, the ring, once installed, should not substantially reduce the minimum diameter (drift diameter) through the connection, while being able to carry generally the maximum axial and torsional loads that can be carried by the pin tips to mobilize the full shouldering potential of the pin ends.
In general terms, the floating shoulder ring of U.S. Pat. No. 6,899,356 may be summarized as comprising a body having a central opening therethrough, a first end face on the body; an opposite end face on the body; an inner surface adjacent the central opening and extending between the first end face and the opposite end face and an outer surface extending between the first end face and the opposite end face; the body having a substantially uniform cross-sectional shape between the first end face; the opposite end face, the inner surface and the outer surface; and the ring being shaped such that its radius to the outer surface varies around the outer surface circumference to form a plurality of lobes.
The plurality of lobes define alternating radially-extending peaks and valleys around the inner surface and the outer surface circumferences. The radial peaks and valleys are contained within two circles having diameters referred to as the outer peak diameter and inner valley diameter. The outer peak diameter is preferably greater than the diameter of the coupling into which the ring is to be installed, so that when placed in a coupling, the peaks engage against the internal surface of the coupling with sufficient radial force to frictionally retain the ring in place and, coincidentally, to largely elastically deform the ring to displace the valleys radially outward and the peaks radially inward to force the ring into a generally circular configuration within the coupling. Preferably, the circumference of the outer surface is selected to be substantially the same as the inner circumference of the coupling into which the shoulder ring is intended to be installed.
The ring fits into the J-space between the pin ends in the coupling such that the inner surface of the ring is open to the coupled tubing string bore. In one embodiment, the inner surface circumference is less than the internal circumference of the pins and greater than the specified or otherwise required drift for the tubing string in which the ring is to be used.
The first and opposite end faces form torque shoulders against which the pin ends of pipe lengths may bear, upon application of sufficient torque across the connection when the pipe lengths are made up into the boxes of a coupling. When the pin ends of the pipe lengths in the coupling are torqued against the ring end faces, the forces cause a frictional response on the ring faces and in the threads, so as to react additional torque and prevent excess penetration of either of the pins into the coupling. In one embodiment, the end faces are substantially planar and/or smooth, to facilitate use as torque shoulders.
Preferably, the ring has a length between the first end face and the opposite end face sufficient to permit each of the pins to bear against the ring, when they are threaded into the coupling. Preferably, the length is selected to prevent excess penetration of the pins into their respective boxes of the coupling and to maintain the made-up pin position within the allowable power-tight position range such as that specified by API.
It is increasingly common for drill strings, casing strings, and production strings to be made up using a pipe-running tool mounted to a rotary top drive. Pipe-running tools, of which there are several known types, incorporate means for releasably engaging either the bore or outer surface of a pipe with sufficient strength to transfer the weight of a pipe section (or a pipe string) to the top drive, and to transfer torque from the top drive to a supported pipe section so as to connect it to, or disconnect it from, a pipe string. The specific mechanisms used to engage the pipe vary from one type of tool to the next, but they commonly incorporate some sort of slips or jaws that can be moved radially outward into gripping engagement with the bore of a pipe (i.e., internally gripping), or radially inward into gripping engagement with the outer surface of a pipe (i.e., externally gripping).
To make up a tubular string using an internally-gripping pipe-running tool, the pipe-running tool is “stabbed” into the box end of a new pipe section that is to be added to the string. The pipe-running tool is actuated to engage and grip the walls of the new pipe section as described above, and the top drive then lifts the new pipe section into position above the upper (box) end of the uppermost pipe section in the tubular string being added to. The top drive then lowers the new pipe section so that its bottom (pin) end enters the box end of the uppermost pipe section in the string. Finally, the top drive is rotated to screw the pin end of the new pipe section into the coupling, thereby completing the operation of adding the new pipe section to the string.
During break-out operations, this procedure is essentially reversed. The top drive lowers the pipe-running tool into engagement with the box end of the uppermost section of pipe in an existing pipe string. The pipe-running tool is then actuated to grippingly engage the upper pipe section. Then, with the lower portion of the string being restrained from rotation by other means, the top drive is rotated to unscrew the upper pipe section from the rest of the string. The removed pipe section is then disengaged from the pipe-running tool and moved to a storage location.
When the box end of a pipe section being added to or removed from a pipe string is fitted with a floating shoulder ring in accordance with U.S. Pat. No. 6,899,356, there can be a risk of the shoulder ring becoming dislodged when the pipe-running tool is disengaged. This risk arises, in the case of an internally-gripping tool, from the possibility of the shoulder ring becoming snagged by the tool's jaws, slips, or other pipe-engagement means, or, in the case of an externally-gripping pipe-running tool, from the possibility of the shoulder ring becoming snagged by the stinger that is typically used to sealingly engage the inside of the pipe with seal elements. Irrespective of the type of tools or equipment used to make up or break-out a pipe string, there is also the possibility that a shoulder ring could become dislodged from a box-end coupling when running any tools or equipment into or out of the pipe string, or if the shoulder ring adheres to the pin end of the pipe section above it. The latter condition could arise due to one or more factors, including metallic or adhesive bonding (perhaps induced by compression and/or torque during joint make-up), and build-up of foreign materials at the interface between the shoulder ring and the pin end of the pipe.
If a shoulder ring is dislodged or lost from a pipe coupling, due to one of the foregoing causes or any other cause, the ring will need to be repositioned or replaced—assuming, of course, that the loss or dislodgement of the shoulder ring is noticed before another pipe section is screwed into the coupling. If the dislodgement or loss of the shoulder ring is not noticed, there will be a corresponding reduction in the torque capacity of the coupling. For these reasons, there is a need for a shoulder ring of the same general type as disclosed in U.S. Pat. No. 6,899,356, but which provides enhanced resistance to dislodgement from a pipe coupling, over and above the resistance afforded by the radial forces exerted by the shoulder ring against the internal surface of the coupling due to elastic deformation of the ring during installation. The present invention is directed to this need.